There are a number of in situ techniques for recovering hydrocarbons, such as heavy oil and bitumen, from subsurface reservoirs. Thermal in situ recovery techniques often involve the injection of a heating fluid, such as steam, in order to heat and thereby reduce the viscosity of the hydrocarbons to facilitate recovery. One technique, called Steam-Assisted Gravity Drainage (SAGD), has become a widespread process for recovering heavy oil and bitumen, particularly in the oil sands of northern Alberta. The SAGD process involves well pairs, each pair having two horizontal wells drilled in the reservoir and aligned in spaced relation one on top of the other. The upper horizontal well is a steam injection well and the lower horizontal well is a production well.
A SAGD operation typically begins in startup mode, in order to establish fluid communication between the injection well and the production well. After startup, the production well can be recompleted for mechanical lift. Mechanical lift can involve the installation of a downhole pump, such as an electric submersible pump (ESP), at the end of an associated production line to provide the hydraulic force for lifting production fluids to the surface via the associated production line. When a production well is completed with a downhole pump, instrumentation including, for example, optical fibers, thermocouples and/or pressure sensors, can be provided running from the surface downward along the pump production line and terminating at and clamped to the downhole pump.
The use of a downhole pump, such as an ESP, involves a number of challenges. For example, the installation of a downhole pump can limit or prevent the possibility of running instrumentation and/or carrying out logging or other operations below the pump into the producing interval of the well. In some scenarios, however, it can be desirable or necessary to monitor reservoir characteristics and/or process conditions below the pump to facilitate evaluation of different parameters (e.g., temperatures, pressures, flow rates, etc.) along the horizontal portion of the well and, in turn, manage well operations based on the collected data.
Conventional methods of getting instrumentation past a downhole pump deployed in a wellbore can involve time-consuming, extensive, and costly wellbore, wellhead and flowline modifications, and represent considerable downtime with various associated inefficiencies. Accordingly, various challenges still exist in the area of techniques for downhole deployment of well instrumentation in thermal in situ hydrocarbon recovery operations.